Design considerations and overall comparisons of artificial lift

Clegg, et al. provides the most extensive and useful listing of the various advantages and disadvantages of lift systems under a broad range of categories. Some of the information is open to interpretation, but, in general, it is the best list of artificial lift advantages and disadvantages available at this time. The information in the tables from Clegg, et al. is a very useful tool for artificial lift selection.

Rod pump

Capital cost

Low to moderate. Increases as depth and unit size increases.

Downhole Equipment

Reasonably good rod design and operating practices needed. Data bank of failures beneficial. Good selection, operating, and repair practices needed for rods and pumps.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Excellent total system efficiency. With full pump tillage, efficiency typically 45 to 60%.

Flexibility of systems

Excellent. Can alter strokes per minute, stroke length, plunger size, and run time to control

Miscellaneous problems

Stuffing box leakage may be messy and a potential hazard. (Antipollution stuffing boxes are available.)

Operating costs

Low for shallow to medium depth (<7,000 ft) land location with low production (<400 BFPD).

System Reliability

Excellent. Run time efficiency >95% if good rod practices followed.

Salvage value

Excellent. Easily moved and good market for used equipment.

System total

Straightforward and basic procedures to design, install, and operate following API specs and RPs. Each well is an individual system.

Usage/Outlook

Excellent. Used on approximately 85% of U.S. artificial lift wells. The normal standard artificial lift method.

PCP

Capital cost

Low, but increases as depth and pump rate increases.

Downhole Equipment

Good design and operating practices needed. May have problems with selection of appropriate stator elastomer.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Excellent. May exceed rod pumps for ideal cases. Typical system efficiency of 40 to 70%.

Flexibility of systems

Fair. Can alter revolutions per minute. VSD on electric drive provides additional flexibility but added costs.  Hydrolic systems are leaky and an environmental problem.

Miscellaneous problems

May have limited service in some areas. Because it is a newer method, field knowledge and experience limited.

Operating costs

Potentially low, but short run life on stator or rotor frequently reported.

System Reliability

Good. Normally over pumping and lack of experience decrease run time.

Salvage value

Fair/poor. Easily moved and some current market for used equipment.

System total

Simple to install and operate. Each well an individual system.

Usage/Outlook

Limited to relative shallow wells with low rates. Used on less than 0.5% of U.S. lifted wells. Primarily gas well dewatering and shallow waterfloods.

ESP

Capital cost

Relatively low capital cost if electric power available. Costs increase as horsepower increases.

Downhole Equipment

Requires proper cable in addition to motor, pumps, seals, etc. Good design plus good operating practices essential.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Good for high-rate wells but decreases significantly for <1,000 BFPD. Typically, total system efficiency is approximately 50% for highrate well but for <1,000 BPD, efficiency typically is <40%. Efficiency can be as high as 60% for large ID equipment.

Flexibility of systems

Poor for fixed speed. Requires careful design. Variable speed drive provides better flexibility.

Miscellaneous problems

Requires a highly reliable electric power system. System very sensitive to changes downhole or in fluid properties.

Operating costs

Varies. If high horsepower, high energy costs. High pulling costs result from short run life especially in offshore operation. Repair costs often high.

System Reliability

Varies. Excellent for ideal lift cases; poor for problem areas (very sensitive to operating temperatures and electrical malfunctions).

Salvage value

Fair. Some trade-in value. Poor open-market values.

System total

Fairly simple to design but requires good rate data. System not forgiving. Requires excellent operating practices. Follow API RPs in design, testing, and operation. Each well is an individual producer with a common electric system.

Usage/Outlook

An excellent high-rate artificial lift system. Best suited for <200°F and >1,000 BFPD rates. Most often used on high water-cut wells. Used on approximately 5% of U.S. lifted wells.

Hydraulic piston pump

Capital cost

Varies but often competitive with rod pumps. Multiple well, central system reduces cost per well but are more complicated.

Downhole Equipment

As with all forms of A/L, proper sizing and operating practices are required for good results. Requires two flow conduits—power fluid to pump, returns to surface. Single tubing string with casing packer most common. Clean power fluid a must.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Good. Typical efficiencies in the 40-50% range.

Flexibility of systems

Excellent. Able to vary injection rate of power fluid, which controls the strokes per minute of downhole pump. Numerous pump sizes and pump-to-engine ratios allow operator to match production rate to delivery of well and to the depth requirements.

Miscellaneous problems

Power fluid control a must in order to protect both the surface pump and downhole pump. Typical total content of suspended solids is 100 pounds or less per 1000 barrels. Of this, none should be larger than 25 microns (.001 dia) and no more than 20 percent of the total suspended solids should be larger than 10 microns (.0004 dia). The remaining 80 percent should be 10 microns or less.

Operating costs

While comparable, it is often higher than for rod pumping systems.

System Reliability

Good with a correctly designed operated system. Wellsite unit minimizes power fluid problems.

Salvage value

Fair. Some trade-in value for triplex pump. Good value for wellsite system, which can be moved to other wells.

System total

Simple well installation. Operating procedures easily learned. Free pump easily retrieved for servicing (no workover rig required).

Usage/Outlook

Good for flexible operation; wide rate range to relatively deep (17,000 feet), high temperature, deviated, oil and water wells, low volume for dewatering gas and CBM wells. Used on less than1% of wells worldwide.

Hydraulic jet pump

Capital cost

Varies but often competitive with rod pump. Costs increase as horsepower requirements increase.

Downhole Equipment

Typically requires a computer design program for sizing. Tolerant of solids, no record of plugging with sand. No moving parts. Long service life for properly designed installations. Easily repaired. Installed and retrieved with power fluid. Easy to operate.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Poor. Maximum jet efficieny in low 30% range. Note: This number cannot be compared to efficiency numbers from other forms of A/L. It is unique to jet pumps. System efficiency is typically in the 10-30%, and this number can be used for comparison purposes.

Flexibility of systems

Excellent. Power fluid rate and pressure adjust the production and lift capacity. Often used to obtain data for PI/IPR curves when the operator plans to use an ESP. Varying the nozzles and throats extends the range of volume and lift capacity.

Miscellaneous problems

More tolerant of power fluid solids. However, the same cleaning is needed as with piston pumps in order to protect the surface pump.

Operating costs

Higher horsepower requirements due to high injection rates. This is offset by long run life for a properly sized pump and low pump maintenance..

System Reliability

Excellent with proper nozzle and throat sizing. Must avoid operating in conditions that lead to cavitation. Triplex maintenance increases with injection pressures above 3500 psi.

Salvage value

Fair to Good. Easily moved to different wells. Some trade in value. Market for triplex pumps.

System total

Computer design programs available for installation analysis. Operating procedures easily learned. Free pump can be repaired at wellsite. Optimum nozzle and throat combination often determined by trial and error.

Usage/Outlook

Good for higher volume wells, flexible operation, depths to 20,000 feet, high temperature, can be made to be completely corrosion resistant, GLR’s of up to 5000, can produce any sand content as long as it is fluidized. Used on less than 1% of well worldwide. Sometimes used to test wells prior to installing ESP’s.

Gas lift

Capital cost

Well gas lift equipment cost low but compression cost may be high. Central compression system reduces overall cost per well.

Downhole Equipment

Good valve design and spacing essential. Moderate cost for well equipment (valve and mandrels). Typically less than 10 valves needed. Choice of wireline retrievable or conventional valves.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Fair. Increases for wells that require small injection GLRs. Low for wells requiring high GLRs. Typically 20%, but range from 5 to 30%.

Flexibility of systems

Excellent. Gas-injection rate varied to change rates. Tubing needs to be sized correctly.

Miscellaneous problems

A highly reliable compressor with 95+% run time required. Gas must be properly dehydrated to avoid gas freezing.

Operating costs

Well costs low. Compression cost varies depending on fuel cost and compressor maintenance.

System Reliability

Excellent if compression system properly designed and maintained.

Salvage value

Fair. Some market for good used compressors and mandrels/valves.

System total

An adequate volume, high pressure, dry, noncorrosive, and clean gas supply source is needed throughout the entire life. System approach needed. Low backpressure beneficial. Good data needed for valve design and spacing. API specs and design/operating RPs should be followed.

Usage/Outlook

Good, flexible, high-rate artificial lift system for wells with high bottomhole pressures. Most like a flowing well. Used on approximately 10% of U.S. lifted wells, mostly offshore.

Intermittent gas lift

Capital cost

Same as continuous-flow gas lift.

Downhole Equipment

Unload to bottom with gas lift valves. Consider chamber for high PI and low BHP wells.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Poor. Normally requires a high injection gas volume/barrel fluid. Typical lift efficiency is 5 to 10%. Improved with plungers.

Flexibility of systems

Good. Must adjust injection time and cycles frequently.

Miscellaneous problems

Labor intensive to keep fine tuned; otherwise, poor performance. Maintaining steady gas flow often causes injection-gas problems.

Operating costs

Same as continuous-flow gas lift.

System Reliability

Excellent if there is an adequate supply of injection gas and an adequate low-pressure storage volume for injection gas.

Salvage value

Same as continuous flow gas lift.

System total

Same as continuous-flow gas lift.

Usage/Outlook

Often used as a default artificial lift method in lieu of rod pumps. Also, a default for low­ pressure wells on continuous gas lift. Used on <1% of U.S. wells.

Plunger

Capital cost

Very low if no compressor required.

Downhole Equipment

Operating practices have to be tailored to each well for optimization. Some problem with sticking plungers.

Operating Efficiency (hydraulic horsepower/input horseposwer)

Excellent for flowing wells. No input energy required because it uses the energy of the well.

Flexibility of systems

Good for low-volume wells. Can adjust injection time and frequency.

Miscellaneous problems

Plunger hang up and sticking is a major problem.

Operating costs

Usually very low unless plunger problem.

System Reliability

Good if well production stable.

Salvage value

Fair. Some trade-in value. Poor open- market value.

System total

Individual well or system. Simple to design, install, and operate.

Usage/Outlook

Essentially a low liquid rate, high GLR lift method. Can be used for extending flow life or improving efficiency. Ample gas volume and/or pressure needed for successful operation. Used on <1% of U.S. wells.

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See also

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